The electrical utility grid or “distribution grid” can be considered to be organized into two general sections: the primary-distribution level and the secondary distribution level. The primary distribution level spans from the point at which electricity enters the distribution grid, through supply substations, step down transformers to feeders that transmit electricity to distribution transformers. The secondary distribution level, spans from these distribution transformers to customer service delivery points. Due to the industry infrastructure operating within the primary-distribution system, such as feeders and step-down transformers, industry personnel can determine the voltage of the distribution grid in the primary distribution level using hardware such as meters. For other primary distribution nodes, voltage can be estimated. Knowledge of this voltage is known as “voltage observability,” or simply “observability.” This primary-distribution-level observability provides power grid operators with the important ability to ensure proper transmission of electricity throughout the primary distribution grid. Unexpected voltage values may reflect improperly functioning equipment, outages, improper maintenance scheduling, unexpected changes in customer consumption, congestion, or other factors that may be hindering the transmission of electricity. Voltage observability on the primary distribution level is able to be accomplished to within a degree of known error through techniques already known and in practice in the art. This observability is vital to the proper operation of the power grid.
The secondary distribution level is defined as going from distribution transformers to the customer service delivery points. Industry operators are not able to determine the voltage at the distribution transformers from which the electricity flows to service delivery points if those distribution transformers do not have hardware such as meters. Electrical impedance causes voltage drop as electricity travels over both primary and the secondary-distribution levels. Because voltage is affected by these losses, the voltage at service delivery points varies as well, and measured voltage cannot be used to determine the voltage at a more distal point of the power grid.
Even if electrical distance were accurately known at all times, other factors affect the voltage at service delivery points as well. The instantaneous amount of power being consumed by the end user, for example, can have a very large effect on the voltage at that service delivery point. When power usage fluctuates rapidly, so does the voltage associated with that power. Thus, the voltage at any given point on the secondary distribution grid may vary at any given time. This situational uncertainty inevitably introduces error into any voltage estimations that do not have voltage observability at the service delivery point.
Just as there are benefits to voltage observability at the primary distribution level, there are benefits to voltage observability at the secondary distribution level as well. Voltage observability at the secondary-distribution level also aids in regulatory compliance; utility operators are required to deliver electricity to end customers within voltage ranges established by the American National Standard Institute (ANSI). Compliance is measured at the service delivery point, and thus without voltage observability at those points, utilities cannot ensure that the product delivered conforms to regulatory standards.
Several attempts have been made to provide voltage observability at the secondary distribution level. Recently, the industry has transitioned from basic, manual read energy meters at service delivery points to using, throughout much of the electrical grid, more intelligent meters capable of telemetering usage, energization status and voltage levels in real time. These smart meters make up part of what is now known as the Advanced Metering Infrastructure (AMI). One of the goals of the transition to smart meters was to give end users and grid operators constant visibility to the properties of and amount of the power used at the end-user delivery points. Unfortunately, the transition to AMI facilitating smart meters has not provided voltage visibility at the secondary distribution grid for various reasons. While most smart meters can be configured to collect and transmit voltage measurements in real time, this has proved impractical in use. The minority of smart meters that are configured to provide voltage measurements in real time are known in the art as “bellwether meters.” Bellwether meters are typically costly to operate in great number due partially to the large amount of bandwidth required to transmit real-time voltage value data. Transmitting such data from a substantial number of bellwether meters would overload modern communications infrastructure. The advanced meter communication infrastructure can typically support only a few bellwether meters per every few hundred smart meters.
While an AMI is comprised of smart meters with voltage alarms, it is impossible to estimate how severe the violations are based on only one voltage alarm setting. As an illustrative example of this, information extracted from setting a single, low voltage alarm of 114 V (the current ANSI range A service low voltage limit) yields the following analysis. A low voltage alarm signal, when accounting for inherent error typical of a majority of smart meters, will identify voltage in approximately the range from 115 V to 113 V or below. Voltage below 114 V is an ANSI range A violation, however, voltage in a range of between 115-114 is still ANSI range A acceptable. At the same time, when the voltage is below 114 Volts, but above 110 Volts (the current ANSI range B service low voltage limit) this is still not necessarily a critical situation, because the ANSI range B limit is not violated. The only conclusion known for certain is that the detected voltage is 115 V or below.
The electrical utility industry has utilized real-time data coming from Supervisory Control and Data Acquisition (SCADA) or Remote Telemetry Unit (RTU) within traditional Conservation Voltage Reduction (CVR) solutions, which provides control actions (of Load Tap Changing [LTC] devices and capacitors, for example) based on observability of the primary distribution system. These primary-distribution-level, RTU or SCADA-based control actions offered little in the way of monitoring voltage constraints at the secondary distribution level, often times leaving utility customers with voltage levels outside of the limits established by the ANSI voltage limits. CVR dependent on RTU or SCADA data alone is often applied on a limited, scheduled basis and is unavailable for more advantageous use, such as when economic considerations would favor utilizing voltage control for electricity demand reduction. Moreover, such CVR does not offer feedback from the secondary distribution level, leaving distribution operators uncertain if residential voltage values satisfy ANSI requirements.
CVR and Dispatchable Voltage Reduction (DVR) are two energy demand-management applications frequently employed within the art to accomplish the reduction of electricity consumption (both power demand and energy). Both CVR and DVR are achieved by changing (typically decreasing) the voltage on a distribution path and can be utilized within Distribution Power Systems as a response to operational requirements such as load peak shaving, to meet economical energy market needs, or for other purposes known within the art. Voltage change can be accomplished within the secondary distribution network through multiple means known in the art, including but not necessarily limited to initiating control actions to modify the parameters of voltage-regulating devices, such as Load Tap Changing (LTC) transformers, Step Voltage Regulators (SVR), and any other similar device known in the art (Voltage Regulating Devices or Voltage Regulator).
Other CVR or DVR solutions, based on AMI service voltage measurements, utilize existing technology known in the art and rely on the assumption that smart meters provide voltage measurements from practically all service points in real-time. As has been discussed, this assumption is incorrect. In practice, only a very small percentage of smart meters can be configured as bellwether meters. Due to changes in the grid topology, it is oftentimes impossible to effectively determine the AMI meters that are at the points of the lowest voltages, and thus grid operators cannot determine whether the voltage values delivered by the few bellwether meters are indicative of the lowest voltages on the grid. These measurements are critical for enacting demand-reduction CVR solutions within industry standardized voltage constraints. Thus, current usage of smart meters on the secondary distribution grid does not provide the necessary voltage observability to enable accurate CVR and DVR solutions.